1. Field of the Invention
The present invention relates generally to water cut meters, and more particularly to a narrow band infrared water cut meter.
2. Description of the Related Art
Unbeknownst to most people outside the petroleum and petrochemical industries, the majority of oil wells around the world produce water along with oil. In fact, in the United States, the average production is 7 barrels of water for each barrel of oil. The average oil and water production of every well is a vital piece of information whose end users range from the field operators to the board room. For example, it is critical for operators to know the relative production of water and oil for each well for royalty allocations and to monitor individual well performance. Field superintendents review well performance to determine field remediation strategies in order to maintain or increase production. Reservoir engineers rely on well performance data to either design or evaluate the effectiveness of water flooding operations. Management looks at the overall field performance including historical oil productions to determine investment and divestment strategies.
In the United States alone, there are probably in excess of 700,000 producing oil wells, all of which are periodically tested for their production of oil, water and gas. Most states mandate this testing at regular intervals, but operators also need the data to properly manage the reservoir. In most cases, well testing will reveal the first signs of problems with a well indicating the need for workover or some form of other treatment.
Years ago, each well was connected to a test separator which would allow the operator to meter the produced oil, water and gas. With the advent of field unitization, a number of wells are now connected to a common production separator through a manifold. This configuration allows a well to be isolated from the combined flow and for diversion of that well flow to a test separator where the individual production of oil, water, and gas are measured.
There are approximately 40,000 test separators in operation today in the United States. In the majority of cases, these are two phase separators which separate the gas from the combined oil and water stream. In this scenario, flow meters measure the gas and combined liquid production. In addition, the operator has to obtain the percentages of the oil and water in the combined liquid stream to determine net oil and water production. This is commonly done by the time-consuming and expensive process of manual sampling or through the use of an online device called a water cut meter.
The other common variety of vessel-type separator is a three phase separator. This type of separator isolates the gas, oil and water so each phase can be metered independently. These separators are more expensive to own and operate and are considerably larger than the simpler two phase separators. In some cases, manual sampling is still used in the oil and water legs of a test separator due to inefficient separation or the propensity of certain oils to bind water in a tight emulsion.
Conventional water cut meters include capacitive water cut meters, density water cut meters, and microwave water cut meters. Capacitive, density and microwave water cut meters have particular limitations. Capacitive water cut meters are limited to detection of oil-water concentrations having a water cut equal to or less than roughly 10%. Over 95% of the oil wells in the United States have water cuts over 10%. While density water cut meters are able to detect a full range of oil and water concentrations (0-100% water cut), gas content of a flow stream prevents accurate water cut detection. Due to the low density of gas, a density water cut meter may view a small content of gas as a large content of oil. Microwave water cut meters, which are one of the more expensive types of water cut meters, are overly sensitive to water salinity and gas content. Also, microwave water cut meters are less accurate for oil-water concentrations on the high water cut end. Microwave water cut meters therefore would be undesirable for applications in which sensitivity is needed for oil-water concentrations on the high water cut end.
Examples of infrared-based sensors for "water cut" measurements are described in McGuire, U.S. Pat. No. 5,105,085, Gregorig, et al, U.S. Pat. No. 4,674,879, and Hines, U.S. Pat. No. 5,331,156. McGuire describes the use of an infrared light emitting diode and an opposing photodiode to determine the opacity of a flow composition. In McGuire, the output of the photodiode is compared to a range of preselected values roughly corresponding to different preselected opacities. The results of this comparison process are displayed by a light-emitting diode panel.
Gregorig describes the use of dual photodetectors to measure both direct and scattered signals in measuring the concentration of oil in water. The Gregorig technique involves directing a substantially monochromatic light beam through an oil/water mixture and measuring the relative intensities of light transmitted directly through the mixture and light scattered by the mixture. The direct and scattered output signals are then normalized by multiplying the signals by predetermined amplification factors. The direct output signal is represented by one equation, and the scattered output signal is represented by another equation.
In Hines, the optical density measurements of a flow stream are made by detecting photons of one predetermined energy where oil and water absorption characteristics are substantially identical and detecting photons of another predetermined energy where oil and water absorption characteristics are similar but not substantially identical. The difference in the absorption values is used to determine the oil and water fractions of a flow stream. Each predetermined energy level corresponds to a wavelength in a wavelength range between 1200 and 1900 nm.